A. Field of the Disclosure
The subject matter of the present disclosure relates to thermally-insulated fluid conduits exposed to natural ground water or seawater at greater than atmospheric pressure.
B. Related Art
The need to insulate buried or submarine fluid conduits arises from temperature dependent impediments to flow including high viscosity, precipitated paraffin, freezing (e.g., natural gas hydrates, sulfur), or vaporization of cold liquids. The temperature above which many of the problems occur changes with pressure and can in some cases be altered by injecting chemicals into the fluid stream of the flow. Insulating fluid conduits can also be used any time arrival temperature is important, for example, when transporting steam or when the liquid would otherwise need to be reheated for processing.
Offshore exploration for hydrocarbon reserves continues to move into deeper waters where the ambient temperature is low and the fluid pressure is high. These conditions increase the viscosity of the carried fluids and increase the chances that natural gas hydrates will form or paraffin will precipitate on the inside wall of the conduit. For these reasons, insulation is often used on submarine pipelines that carry viscous liquids or transport liquefied gas between LNG tankers and onshore terminals, on flow lines that transport oil between submerged wellheads and offshore platforms and the wellheads, and on piping associated with these pipelines and flow lines. Insulating the fluid conduit can ensure that the carried fluids reach their destination without exceeding a temperature at which the resulting problems are serious enough to justify the cost to insulate the pipeline or piping. This temperature, whether precisely quantifiable or not, may be referred to herein as the “acute temperature.”
Conventional insulating materials typically used at or near atmospheric pressure rely on the low thermal conductivity of gases (compared to liquids and solids). To mitigate thermal convection the gaseous volume is divided into minute spaces in porous solids or between finely divided solids, such as mineral wool or particulate matter. This reduces the so-called “characteristic length”, an important parameter in the physics of convection. Any convection that remains is normally only considered as it appears in the “effective thermal conductivity,” a value that is deduced using an artificial assumption that all heat transfer is by conduction. Aerogels are microporous solids that are so finely divided that they are mostly gas, and the dimension of the pours are on the order of the mean free path of the gas. By a phenomenon known as the Knudsen effect, the thermal conductivity of these microporous solids is less than the thermal conductivity of the confined gas. More recent studies have shown that the Knudsen effect also appears in finely divided solids filled with liquids.
Dense liquids usually fill the annuli between the tubing and casing or between casing layers in wells that produce liquids and gases from geological formations. The primary purpose of these dense liquids is to keep bottom-hole pressure in the annulus higher than the pressure of the reservoir so that produced fluids will rise through the tubing and not the annuli. In recent years, some fluids have been developed for the secondary purpose of enhancing properties that thermally insulate the production tubing. This has been done with fluids that gel at elevated temperature to eliminate convection (See e.g., U.S. Pat. Nos. 3,642,624 and 3,831,678, 8,236,736). More recently other fluids used for this purpose remain liquid but rely on increased viscosity to mitigate convection (See e.g., U.S. Pat. Nos. 3,618,680; 4,877,542; 8,186,436; 5,707,939; 5,712,228; 7,863,223 and US Pat. Pub. 2004/0087448; 2012/0208728). Insulating concrete has also been proposed for cementing casing (U.S. Pat. No. 4,822,422). Double wall tubing with an evacuated annulus is sometimes used to better insulate the production tubing (see http://www.offshore-mag.com/articles/print/volume-61/issue-2/news/flow-assurance-vacuum-insulated-tubing-helps-solve-deepwater-production-problems.html)
Piping and pipelines that operate at atmospheric pressure are usually insulated with conventional insulating materials as described above, but fluid conduits that are installed below grade or below sea level present special problems. Conventional polymer foams are sometimes covered in a flexible, waterproof plastic outer jacket or cover, but the depth at which this can be used is limited by the external hydrostatic pressure at which the porous insulation composite will collapse. Pipelines insulated in this manner have been plagued by leaks at the field joints or by punctures in the outer jacket.
In deeper water, offshore pipelines are sometimes insulated by installing conventional cellular foam or aerogel in the annulus between the fluid conduit and a coaxial outer pipe or casing that resists collapsing under seawater pressure (see U.S. Pat. No. 6,142,707). The French company ITP Interpipe SA offers encased aerogel or “microporous solid” insulation in a partially evacuated annulus. (See U.S. Pat. No. 6,145,547; French Pat. No. 2,746,891). This reduced gas pressure further reduces the effective thermal conductivity.
The deeper the ambient water head, the thicker the casing must be to resist collapse, making it heavier and requiring more time to weld together. If the pipes are spooled, the welding is done onshore. This cost can be less than welding on the lay barge, but the larger of these encased pipelines are too stiff to spool. In very deep water, where the suspended length in the lay process is long and the casing is thick, the collapse-resistant casing can make the pipeline so heavy as to be economically infeasible to install with any existing equipment. An attempt to reduce the wall thickness and the weight of the outer casing by pressurizing the annulus of an insulated flow line was thwarted in one project by an unanticipated large increase in the overall heat transfer coefficient. This was largely a result of increases in convective heat flow in the pores of the insulating composition (see https://www.onepetro.org/conference-paper/OTC-13074-MS).
Waterproof, collapse-resistant insulating materials that can be used underwater without a collapse-resistant, waterproof jacket are known in the prior art for insulating submerged piping and pipelines. Such materials avoid the costs and weight associated with using and welding the steel outer casing. These materials are hereinafter referred to as “wet insulation” or “wet insulating materials.” The International Standards Organization is developing a standard entitled “Wet Thermal Insulating Coatings for Pipelines, Flow lines, Equipment and Subsea Structures”” (ISO/DIS 12736). The materials that have been used include rubber, polyurethane, elastomeric silicone, polypropylene, bitumen (See e.g., U.S. Pat. Nos. 6,182,705; 6,155,305; 5,871,034; and 6,092,557), polystyrene, and hydraulic cement (See U.S. Pat. No. 5,476,343).
In order to reduce the thermal conductivity, these wet insulating materials are sometimes extended with tiny air bubbles (in high density polymer foam), cork (in ebonite), closed cell fillers, or collapse-resistant spheres. In bituminous compositions, it has been proposed that such cellular fillers can help physically stabilize the bitumen at elevated temperatures (See U.S. Pat. No. 6,155,305). The savings in cost associated with casing pipes and welding afforded by wet insulation is weighed against the higher thermal conductivity (4 to 5 times) and higher cost per unit volume compared to conventional insulation. Despite these disadvantages, such materials can be cost-effective where moderate thermal resistance (the reciprocal of heat transfer coefficient) is needed, or where the water is so deep that the weight of encased insulation makes pipe installation infeasible.
Adhering wet insulating materials reliably to adjacent materials has been a technical challenge in practice. Wet insulation is pre-applied to the individual pipe joints, leaving a few inches of bare pipe at each end to allow field welding of the pipes together before the field joint insulation is applied. Pipelines have failed as a result of water ingress thorough interface of the insulation with the adjacent factory applied insulation. A consensus has emerged among the leading companies in the business of offshore hydrocarbon exploration and production that wet insulation must bond to adjacent materials so as to exclude water from the interfaces. If the pipes are joined on the pipe lay vessel, the time spent applying the field joint insulation that exceeds the time needed to weld the pipes is very costly.
Some of the preferred wet insulating materials, especially polypropylene, are notoriously antagonistic to adhesives. Bonding is more difficult at the axial interface of field joints because this bond is subject to long term cyclic thermal stresses that can vary with radius. In theory, hot fusing thermoplastics can create a seamless, cohesive bond, but in practice this is made difficult by the high coefficient of thermal expansion and low conductivity of the materials. Preheating of factory applied insulation takes time, and shrinkage upon cooling causes the materials to separate at the interface unless pressure is maintained on the field joint material until the bond solidifies. That makes cohesive bonding a costly approach when the pipeline is strung offshore, especially thick insulation. A unique difficulty of using bituminous materials is that the bond strength quickly diminishes when the bitumen softens at elevated temperature. Wet insulation that withstands higher temperatures is needed for hotter and deeper wells now being drilled. Unless a new approach is introduced they will cost even more than wet insulation of the prior art.
Insulating pipelines with materials that change from a solid to a liquid as the pipeline warms (phase change materials) is known in the prior art. (See U.S. Pat. No. 6,116,290). The essence of this technique is not the use of the phase change material in the liquid phase as insulation, but rather that the latent heat of melting is added to the heat that passes through separate insulation that surrounds it. This extends the time window for injecting hydrate or wax inhibiting chemicals that will enable a cold start of flow lines that carry hydrocarbons. The corollary of that benefit is that more heat is absorbed by the phase change material once the line is started, thereby possibly requiring injection of more hydrate or wax inhibiting chemicals.
Electrically insulating liquids have been contained in the annulus between a submerged pipe and a high voltage power transmission conductor to electrically insulate the conductor from seawater. In general, the acute temperature limits the length of a pipeline unless heat is added, because the longer the line the more heat is lost. This in turn limits the geographic area that can be served by a single offshore production platform receiving produced hydrocarbons from satellite wells on the sea bed.
Direct heating is a technique in which pipe is heated by passing enough electrical current through it to create resistance heating in the pipe itself. Where alternating current is used, the method is also known as “impedance” heating (See Epstein, Fred S. and White, Gary L., Understanding Impedance Heating, Chemical Engineering, pp. 112-118, May 1996). This has been proposed for use on pipelines with encased insulation when the line pipe is electrically insulated from an electrically conductive casing. Some waterproof insulating materials of the prior art (rubber and polypropylene) are also good waterproof electrical insulators so no additional tasks are added to the pipe laying process. This makes it conceptually ideal for heating offshore pipelines.
Because the electrical resistivity of steel is so much lower than seawater, direct heating can and has been used to heat pipelines that are protected with anodes (Lervik, Jens Kristian et al, Direct Electrical Heating of Subsea Pipelines, Proceedings of the Third (1993) International Offshore and Polar Engineering Conference, Jun. 6-11, 1993, vol. II, pp. 176-184; Ahlen, C. H., Electric Heat Tracing of Submarine Pipelines Induction Heating by the Statoil Invented “ITTI”—System, Proceedings of the First (1991) International Offshore and Polar Engineering Conference, Aug. 11-16, 1991, vol. II, pp. 331-334). This method is limited to warming the pipeline from a cold start because the cost of generating enough heat to warm the pipe and make up for the current lost through anodes makes continuous long term heating economically uncompetitive with encased insulation.
Doing away with the anodes on pipelines with wet insulation has been proposed (see U.S. Pat. No. 6,049,657) but even a small current leak at a field joint could be catastrophic. No wet insulation system of the prior art has yet inspired enough confidence to take that chance, partly because conventional insulating materials reduce heat flow so much better than wet insulating materials that in most real situations the applied cost of the popular wet insulation materials plus the present value of future heat generating costs would be more expensive than investing in more costly, but far more effective encased insulation and paying less to replace lost heat.
So-called “active heating” of pipelines by pumping a heated liquid though an annulus between a production pipe and an insulated casing has been used to warm offshore pipelines in the prior art long enough to enable “cold starts” (see http://e-book.lib.sjtu.edu.cn/otc-03/pdffiles/papers/otc15188.pdf). In a variation on this theme, it has been proposed to pump a heated liquid through a tube that runs through an insulated annulus (see U.S. Pat. No. 6,955,221)
The subject matter of the present disclosure is directed to either reducing the cost to insulate fluid conduits in high ambient pressure, or overcoming or at least reducing one or more of the problems set forth above.